Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer. Thus, the porous layer forms a reservoir, that is, a volume in which hydrocarbons accumulate. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit. The drilling mud also carries cuttings from the drilling process back to the surface as it travels up the well bore. As drilling progresses downward, the drill string is extended by adding more pipe sections or “joints.”
A modern oil well typically includes a number of tubes extending wholly or partially within other tubes. That is, a well is first drilled to a certain depth. Larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. After the initial section has been drilled, cased, and cemented, drilling will proceed with a somewhat smaller well bore. The smaller bore is lined with somewhat smaller pipes or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A well may include a series of smaller liners, and may extend for many thousands of feet, commonly up to and over 25,000 feet.
As noted, liners are cemented in the well bore as the well is constructed. That is, the liner necessarily is smaller than the well bore in which it is installed. That gap between the liner and the well bore is referred to as the annulus, and it is filled with cement after the liner has been installed. The cement helps to secure the liner in the well bore and protect it against corrosion and erosion. It also supports the borehole walls from collapse. Most importantly, the cement is intended to form a complete seal around the liner. Hydrocarbons and other fluids in the formation thus are prevented from migrating to the surface. If the liner leaks, the cement also helps to ensure that fluids flowing through the liner do not contaminate the surrounding formation, and especially water-bearing formations. A complete seal also gives more precise control over stimulation processes, such as fracturing and acidizing, and avoids unintentional stimulation of untargeted zones.
The liner is cemented in the well bore by injecting cement, that is, a cementitious, settable slurry down the liner and allowing it to flow up the annulus. The cement is allowed to set, that is, solidify and harden into what hopefully will be a continuous seal throughout the annulus. The chemical composition and properties of drilling mud and cement slurries, however, are quite different. If drilling mud mixes with the cement slurry, the cement will not set properly. Drilling mud, especially gelled drilling muds, also can be difficult to displace from the well bore. Other drilling muds, such as oil-based and synthetic muds, contaminate the surface of the well bore. Residual drilling mud and oily residue can prevent the cement from forming an intimate, continuous bond with the liner and formation. The cement may be weakened in certain areas, or there may be flow paths through it.
The liner and well bore, therefore, typically must be cleaned before cement is injected. Fluid may be injected under turbulent flow to thin and disperse drilling mud—a process referred to as washing or flushing. In addition, a volume or “pad” of fluid typically will be injected ahead of the cement. The pad of fluid, commonly referred to as a cement spacer, separates the cement from the drilling mud. It also will displace drilling mud and clean the well bore.
Spacers may include additives designed to thin the mud. Especially if the drilling mud is oil-based, surfactants will be added to ensure that the well bore is water-wetted and that there will be intimate contact with the aqueous cement. It is essential, however, that the spacer fluid be heavier than the drilling mud. That is, the spacer must have a greater density than the mud which it is intended to displace. It also must be thicker, than is, it must have a higher viscosity and yield point than the drilling mud. Spacer fluids are water based, however, and water typically is both lighter and thinner than drilling muds.
Thus, spacer fluids typically incorporate weighting agents, such as fly ash and barite. While they may have other effects, weighting agents primarily are intended to increase the density of the spacer. They typically are fine, relatively inert solid particulates. A gelling and suspending agent, such as welan, gellan, xanthan, and galactomannan gums, will be added to suspend the weighting agent particles. The suspension agent also will tend to increase the viscosity and yield strength of the spacer fluid, thus increasing its effectiveness in pushing out the drilling mud.
While many particulates have been identified as potential weighting agents, most commercial spacer fluids rely on fly ash, barite, calcium carbonate, hematite, and hausmannite to increase the density of the fluid. The economics and characteristics of a particular well may render it more suitable to a particular spacer fluid and cement. The fluids may provide extraordinary results in one well and be completely unsuitable for use in another. Thus, general statements should be taken as such, and not as definitive, immutable principles. Nevertheless, such weighting agents have been used widely and are viewed by many as providing superior spacer fluids.
At the same time, conventional spacers using the more common weighting agents suffer disadvantages. For example, a weighted spacer fluid should maintain a stable viscosity and hold solids in suspension over time and temperature. If the fluid becomes too thin once it is injected into a well, the weighting agent may settle out. It also may no longer be able to displace drilling mud from the liner. Residual weighting agents and mud can impair the operation of tools in the liner or the continuity of cement in the annulus.
On the other hand, if a weighted fluid becomes too thick, friction between the fluid and liner will increase. The liners, as noted, may extend for many thousands of feet, and friction losses over such distances can be significant. Greater pressure will be required to pump the fluid, increasing the cost of the operation. Increased hydraulic pressure also can damage the formation by pushing drilling mud or other fluids into the formation.
Such considerations are especially critical if a cementing operation is interrupted for any reason. The spacer fluid may remain in a well, and be subject to elevated temperatures in the well for extended periods of time. Cement jobs also have become more extensive. Liners have greatly increased in length over the past several years, as has the amount of spacer fluid pumped through the well. The bore hole may extend as far as 7,000 feet and may require over 150 barrels of spacer to clean it. Thus, even if all goes well, the residence time of spacer fluids in the well may be substantial.
The rheology of conventional spacer fluids, however, may not be stable under such conditions. The weighting agent may tend to settle out in many fluids, or the fluid tends to thicken if its residence time in the well is extended from any reason.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved fluids for spacer fluids and, and more particularly, to spacer fluids that are more tolerant of delayed, interrupted, and extended cementing operations. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.